Tanks & Terminals - Summer 2021

SUMMER 2021 21

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CONTENTS Summer 2021 Volume 07 Number 02

03 05 06

Guest comment World news Turning the corner

25

ISSN 1468-9340

Keeping things grounded Bruce Kaiser, Lightning Master, USA, outlines two different approaches to storage tank grounding.

Gordon Cope, Contributing Editor, predicts a hopeful future for the tanks and terminals sector in North America.

29

Safety blanket Jim DeLee and Richard Koeken, Fluid Components International, USA, discuss the importance of thermal flow meters for safety-critical nitrogen tank blanketing.

33

Isolating instrumentation Tai Piazza and Greg Tischler, VEGA Americas, USA, present two case studies to emphasise the importance of being able to isolate instrumentation on a valve and still receive reliable level measurements.

37

Data for long-term decisions Ryan Gane, ROSEN, USA, examines how technology that can collect high-resolution data of tank bottoms can help enable long-term integrity management plans.

39

To spray or not to spray?

Ian Wade, Belzona Polymerics, UK, outlines the benefits of protecting storage tanks with sprayable, polymeric coatings.

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14

The changing landscape of tank storage Saskia Huber, Linde, Germany, evaluates the changes faced by the tank storage sector at every level.

19

Ted Huck, MATCOR Inc., USA, explores cathodic protection options for terminal marine structures including docks, jetties, piers, seawalls and pilings.

The time is now Bernat Sala, TECAM, Spain, outlines the vital role that environmental technologies have to play in the tank storage sector.

Protecting marine structures

45

Decommissioning spotlight Richard Vann, RVA Group, UK, explores the process and benefits of asset retirement planning, and why operators should start thinking about the end of a tank’s life earlier than expected.

Cracking a cold case J. Randolph Kissell, Trinity Consultants, USA, solves a cold case, and outlines how to size wind girders for tanks of any diameter.

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Just On cryogenic tanks, a dedicated tank base insulation system, can help protect against heat transfer, settlement, ground heaving, product leakage and more.

Learn more about the general design considerations for these applications and how the unique properties of cellular glass insulation make it an excellent choice for tank base systems.

Copyright© Palladian Publications Ltd 2021. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK.

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Gordon Cope

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T

he liquid terminal industry has never been more vital than it is today. I am proud every day to work for our community of terminal industry professionals, ensuring that our industry’s voice is heard by policymakers.

I am also committed to ILTA’s role as a convener, bringing together industry peers from across our nearly 80 terminal member companies to network, share challenges, and identify solutions.

In 2020, the global COVID-19 pandemic meant that we had to find new ways to bring people together. We were forced to make the unfortunate decision to cancel our landmark event held in Houston each year – the ILTA Annual Operating Conference and Trade Show.

For similar reasons, in 2021 we have rescheduled our event for 4 – 6 October. Next year, we will return to our traditional schedule and hold the show in June. These are therefore exceptionally busy times for ILTA this summer – registration is open for October 2021 and we are in full gear to deliver a well-attended, high quality event. At the same time, we are launching our 2022 ‘Call for Proposals’ to help us identify new session topics that are as insightful, timely, and important as our conference audience has come to expect from us. We invite everyone to consider submitting their session ideas; for more information, please visit www.ilta.org.

Adjusting to the realities of the pandemic also meant that ILTA needed to make a strong pivot to virtual to continue to serve our membership. Between April 2020 and April 2021, our Environment, Health, Safety and Security Committee and its subcommittees met four times in an all-virtual format. Our attendance and engagement at these meetings were record-shattering. We have learned a great deal from our year of virtual experiences and, going forward, we are committed to a hybrid approach for our meetings, which will allow members the option of virtual or in-person attendance. While there is nothing like the experience of in-person interaction for networking and learning, we have seen that virtual attendance can also be a meaningful way to deliver value to our membership.

One thing that did not slow down during the pandemic was the need for advocacy on behalf of the terminal industry in Washington D.C. The pace of our advocacy work has only accelerated since President Biden entered the White House earlier this year. The Biden administration has prioritised investing in the US’ infrastructure and has called out critical energy infrastructure as a particular focus. ILTA is leveraging the infrastructure discussion in Washington to explain the key role that liquid terminals play in providing storage, blending, and logistics to facility fuel supply lines.

The cyberattack on the Colonial pipeline heightened awareness of our energy supply lines even further. ILTA reacted quickly to the shutdown, convening members to identify points of concerns to relay to federal agencies. We quickly learned that targeted, temporary waivers from the Coast Guard and EPA could allow terminals to take actions that could increase the resilience of the system overall. In the after-action reports that will follow, we look forward to working with the agencies to ensure that these waivers are considered – and granted – quickly in the event of a similar future challenge. We are also creating a new Cybersecurity Working Group, through the leadership of our Security Subcommittee, to identify other ways we can support our membership in strengthening their cybersecurity.

Every year brings new challenges and opportunities to learn. We are all coming out of an exceptional year of challenges and learning. I am looking forward to applying these lessons to our work ahead, so that ILTA can support its members as they build a stronger, more resilient terminal industry.

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WORLD NEWS A selection of some of the latest news hitting the headlines on www.tanksterminals.com...

DIARY DATES

Natural gas storage capacity remained essentially unchanged in 2020

31 August - 02 September 2021

According to the US Energy Information Administration (EIA), natural gas storage capacity remained essentially unchanged in 2020; however, some operators revised earlier estimates, increasing working gas capacity.

23rd Annual Aboveground Storage Tank Conference & Trade Show Orlando, Florida, USA www.nistm.org

13 - 16 September 2021

Mitsubishi Power and Texas Brine join forces for hydrogen storage

Gastech Singapore www.gastechevent.com

Mitsubishi Power and Texas Brine have joined forces on large-scale hydrogen storage solutions to support decarbonisation efforts in eastern America.

Woodside to exit Kitimat LNG

ILTA 2021 Houston, Texas, USA www.ilta.org

05 - 07 October 2021

Siemens Energy to supply equipment for gas storage project in Uzbekistan

AFPM Summit New Orleans, Louisiana, USA www.afpm.org/events

Siemens Energy has been selected to supply two low-emission compression trains for Phase I of the Gazli underground gas storage (UGS) project in the Bukhara region of Uzbekistan.

Invenergy and BW LNG have completed the financing of the floating storage and regasification unit (FSRU) component of the Energía del Pacífico (EDP) LNG-to-power project in El Salvador.

Global Energy Show Calgary, Canada www.globalenergyshow.com

04 - 06 October 2021

Woodside has decided to exit its 50% non-operated participating interest in the proposed Kitimat LNG development.

Invenergy and BW LNG close finance for FSRU

21 - 23 September 2021

01 - 02 December 2021 14th Annual National Aboveground Storage Tank Conference & Trade Show The Woodlands, Texas, USA www.nistm.org

08 - 10 March 2022 StocExpo Rotterdam, the Netherlands www.stocexpo.com

READ MORE...

To read more about all of these stories, and keep up to date with the latest news and developments in the storage sector, visit www.tanksterminals.com and follow us on our social media platforms.

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5

Summer 2021

Summer 2021

6

T

Gordon Cope, Contributing Editor, predicts a hopeful future for the tanks and terminals sector in North America.

anks and terminals in North America have had a challenging year, as everything from pandemics to extreme weather has had an impact on both assets and future planned growth. But the sector remains strong, with tantalising opportunities for new fuel infrastructure just over the horizon.

Crude storage hubs The Cushing, Oklahoma, storage hub experienced several large oscillations in storage throughout 2020. Normally, the hub, which acts as the delivery point for NYMEX crude oil futures contracts, averages roughly 45 million bbl of storage. When demand crashed in April 2020, stocks climbed to 65 million bbl (about 83% of the site’s working storage capacity), causing panic-trading that saw prices enter into negative territory for the first time. While stocks

diminished to around 40 million bbl in mid-2020, they had begun to climb again in late 2020 above 80% capacity.

In late 2020, Enbridge purchased the Cushing assets of Blueknight Energy Partners for US$132 million. The deal saw the transfer of 34 storage tanks with a total capacity of 6.6 million bbl. This lifts Enbridge’s hub storage capacity to approximately 26 million bbl. The company commented: “This acquisition will provide connectivity to new production basins, Oklahoma and the Rockies, and support Enbridge's strategy for directing barrels to the US Gulf Coast.”

In Canada, production and exports are on an upward trajectory. Oil output in Western Canada is expected to rise from 3.9 million bpd in 2020 to 4.45 million bpd by the end of 2021. Canada now exports approximately 3.8 million bpd to the US, which is expected to rise to

7

Summer 2021

4.2 – 4.4 million bpd by 2026. Pipeline expansions in progress will add almost 1 million bpd capacity by 2025, and crude-by-rail capacity is continually growing.

To handle growth in Canada, Gibson Energy has earmarked up to CA$200 million for tank expansion projects, primarily at its Hardisty and Edmonton terminals.

The company had approximately 12 million bbl of storage at the end of 2020, and is expected to add between two and four 500 000 bbl tanks in 2021 at Hardisty. Gibson also recently entered a 25-year contract to supply Suncor Energy with biofuel services at its Edmonton terminal. Under the agreement, Gibson will add substantial blending, storage and transportation infrastructure to its terminal (which sits adjacent to Suncor’s refinery) in order to handle the company’s renewable diesel production.

Export terminals For the last two years, Alta Gas has been operating the Ridley Island propane export terminal (RIPET) in Prince Rupert, British Columbia. The CA$500 million terminal (which can ship tanker loads to East Asia in 10 days) has an advantage over Gulf of Mexico suppliers (which can take up to 4 weeks). In 2020, it averaged 39 000 bpd of exports. The availability of propane is expected to grow as production of shale gas from the Montney formation in northeastern British Columbia continues to expand, and Alta Gas has federal approval to enlarge RIPET by 40 000 bpd. Pembina Pipelines has been building a Greenfield CA$250 million terminal on nearby Watson Island with a capacity of 25 000 bpd, and expects the facility to be commissioned in mid-2021; the company already has a further 15 000 bpd expansion in the engineering phase.

In the US Gulf Coast (USGC), COVID-19 had a significant negative impact on planned deep water export terminals. In early 2020, there were a dozen proposals to build facilities that could accommodate very large crude carriers (VLCCs) capable of carrying up to 2 million bbl to market. A significant drop in Permian production as well as decreased consumption in consumer markets took the urgency out of export plans, and there are now only three active proposals before federal maritime regulators.

Phillips 66 and Trafigura are slow-walking their application for the Bluewater Texas terminal (BWTX) project in Corpus Christi. Enterprise Product Partners and Enbridge’s Sea Port Oil Terminal (SPOT) in the Houston Ship Channel are pushing the approval process into latter 2021, and Sentinel Midstream has suspended permit reviews for the Texas GulfLink deepwater port in Freeport.

Not all tanks and terminals activity in the USGC is stalled; in mid-2020, Moda Midstream commissioned the final 500 000 bbl tank in a 10 million bbl expansion at its Moda Ingleside Energy Center (MIEC) in Ingleside, Texas.

The expansion now gives the company approximately 12 million bbl of storage to help producers facilitate the export of crude through Moda’s terminal in Taft, Texas. In addition, Moda has announced a new phase of construction that will add a further 3.5 million bbl of storage.

Summer 2021

8

LNG In December 2020, Corpus Christi LNG facility in Texas commissioned its third and final liquefaction unit. The US currently has 10.8 billion ft3/d of LNG capacity at six facilities in the USGC, and was running in excess of 90% capacity during the busy winter heating season. The US Energy Information Administration (EIA) forecasts that LNG exports will average 8.5 billion ft3/d in 2021 and 9.2 billion ft3/d in 2022.

In Western Canada, the Montney and Duvernay shales of northwest Alberta and northeast British Columbia contain trillions of cubic feet of gas and immense reserves of NGLs. Output now stands at 5.6 billion ft3/d of liquids-rich gas. While most of the gas is currently processed and distributed through Alberta to markets in Eastern Canada and the US, plans are underway to tap an entirely new market. The west coast of Canada is significantly closer to Asia than Australia or the USGC, making LNG transport much more economical. LNG Canada, led by Royal Dutch Shell, is building a plant in Kitimat, British Columbia, with a capacity of up to 26 million tpy.

Challenges Recent inclement weather has had an impact on storage assets in North America. The strategic petroleum reserve (SPR) facility in West Hackberry, Louisiana, was hit by Hurricane Laura in August 2020. The SPR has a total of 648 million bbl of crude stored in four underground caverns; West Hackberry holds slightly under 200 million bbl. The hurricane temporarily disabled surface installations and power, but did not damage any assets below ground.

The natural gas system in Texas was not so fortunate.

A Polar vortex hit the state in February 2021, causing gas wells to freeze and production to drop from around 24 billion ft3/d to as low as 11 billion ft3/d. The outage should not have been an issue; Texas has a large amount of gas storage, approximately 500 billion ft3 (about 10% of the nation’s total), and it was topped up with 300 billion ft3 when the storm hit. The system is rated to deliver up to 17.5 billion ft3/d. Therefore, it can be concluded there should not have been a gas storage.

The weather crisis illustrated weaknesses in the state’s gas delivery system. Most natural gas pipes are filled with associated gas derived from shale oil wells because it is easier to access under normal conditions. However, unlike gas in storage caverns, which are pressurised and can flow under their own power, associated gas needs to be pumped by compressors into the pipeline system. When power lines supplying Permian basin fields failed, compressors went down, leaving the gas stranded.

Several issues compounded the problem. First, theoretical and actual extraction rates from underground storage can differ due to pressure fluctuations. Unlike storage systems under federal jurisdiction, Texas’s state-run system does not necessarily have to prioritise energy utilities over other users, such as fertilizer or petrochemical plants. Spot prices quickly soared from US$4.50/million Btu to US$400.

In the end, the disruption caused widespread physical hardship and billions of dollars in commercial losses. The working storage capacity in Texas is deemed sufficient to meet needs; delivery capacities can be improved through engineering. However, analysts note that a comprehensive overhaul of regulations and procedures governing gas storage and delivery during emergency situations is needed in order to avoid similar catastrophes in the future.

The emergence of COVID-19 and the ensuing crash in demand hit refineries hard. While the US has a refining capacity exceeding 18.6 million bpd, output shrank as low as 13.3 million bpd in April 2020. Demand destruction during lockdowns was the main culprit, but refineries also ran out of room onsite to store diesel and gasoline.

Producers turned to vessels, rail tankers and fuel trucks to store product, but were eventually obliged to mothball facilities. In April 2020, Marathon idled its 165 000 bpd refinery in Martinez, California, as did operators of the 130 000 bpd Come-by-Chance refinery in Newfoundland.

By the end of 2020, the US had permanently lost around 600 000 bpd of refining capacity, including the 335 000 bpd Philadelphia Energy Solutions plant in Philadelphia.

Biodiesel is offering some refineries an opportunity to persevere. CVR Energy is revamping its 74 500 bpd refinery in Wynnewood, Oklahoma, to produce 100 million tpy of renewable fuel. The US$100 million project will see an existing hydrocracker reconfigured using Haldor Topsoe’s HydroFlex technology to convert soybean oil to ASTM D975 biodiesel that is compliant with the California low carbon fuel standard. The re-fit is expected to be completed in mid-2021

The future The potential for hydrogen as an environmentally-friendly transportation fuel has grown dramatically over the last several years.

The world currently produces around 75 million tpy, primarily using the steam-methane reforming process, where high-temperature steam is used to strip hydrogen from natural gas. This has consequences for the atmosphere; the International Energy Agency (IEA), estimates that greenhouse gas (GHG) emissions associated with the production amounted to roughly 830 million tpy of CO2e.

At the end of the tailpipe, however, hydrogen is a boon; when it is consumed in a fuel cell to produce electricity, the only emission is water. If the hydrogen produced in North America (about 12 million tpy) were used as a fuel, it would power up to 40 million fuel cell vehicles annually.

The key to environmental neutrality is to purify the hydrogen without emitting GHGs. So-called blue hydrogen is made using the steam-methane process, but the carbon dioxide is captured and sequestered underground (CCS).

Hydrogen can also be made with electrolysis (running an electric current through water to separate hydrogen from oxygen). If the electricity is sourced from solar or wind power, the output is called green hydrogen.

Many nations in Europe are already developing hydrogen hubs (also called hydrogen valleys and hydrogen Summer 2021 10

clusters). The EU has developed plans to build up to 40 GW of renewable hydrogen electrolysers and produce as much as 10 million t of renewable hydrogen by the year 2030.

Government and energy companies are now looking at potential sites in Canada, especially to develop blue hydrogen. Fluor Canada built Royal Dutch Shell’s Quest Carbon Capture & Sequestration facility at the Scotford refinery outside of Edmonton, Alberta. The engineering firm also designed the nearby North West Redwater Sturgeon refinery, which captures carbon for transport via the Alberta carbon trunk line to enhanced oil recovery projects in central Alberta. The existing infrastructure can readily be adapted to hydrogen.

In other parts of the country, green hydrogen has great potential. Canada derives almost 60% of its electricity from hydro power, primarily in Quebec and British Columbia.

Hydro-Quebec has commissioned Thyssenkrupp to build an 88 MW water electrolysis plant in Varennes, Quebec. When the plant enters service in 2023, it will generate 11 000 tpy of green hydrogen, which will then be used to generate biofuels. A consortium is also looking at building a similar plant in British Columbia.

In the US, SGH2 announced plans to build the world’s largest green hydrogen production facility in Lancaster, California, north of Los Angeles. The plant will combust mixed waste paper in a plasma gasification technology partially developed by NASA to produce up to 3.8 million kg/yr of hydrogen fuel for use in the state. The plant is expected to be commissioned by 2023.

To deal with infrastructure issues, two major hydrogen equipment suppliers, Chart Industries and Matrix Service Co., have entered into a joint venture to provide standardised hydrogen fuel solutions to the North American market. With long histories in the cryogenic sector, the duo expect to provide a wide range of liquefaction, transportation and regional storage facilities for the retail distribution of the fuel.

Hydrogen still has several major hurdles to overcome; the biggest barrier is price. In 2019, S&P Global estimated that conventional hydrogen cost €1.24/kg to produce, blue hydrogen stood at €1.31/kg, and green hydrogen at €3.43/kg. Scaling up to major production is bound to lower costs; European advocates estimate that green hydrogen could be as low as €1.70/kg by mid-decade. If that is the case, hydrogen fuel could skyrocket. Analysts project that the global hydrogen market could reach US$12 trillion by 2050, when up to 30% of fuel needs will be met by hydrogen.

Conclusion While disruptions due to COVID-19 and weather have caused major upsets to the energy sector, tanks, terminals and other infrastructure have shown remarkable flexibility and the ability to adapt. In the near term, domestic consumption will recover and export opportunities for all forms of energy will continue to grow. Over the longer term, the emergence of hydrogen as a major fuel source could create significant opportunities for tanks and terminals in North America, as well as around the world.

Bernat Sala, TECAM, Spain, outlines the vital role that environmental technologies have to play in the tank storage sector.

W

hat is environmental technology? The answer to this question can include solar panels, wind turbines, or regenerative thermal oxidiser (RTO) for emissions treatment. In general, environmental technology involves the development and application of products, equipment and systems aimed at reducing the negative impact of human activities on the environment.

11 Summer 2021

almost US$30 billion.1 The report affirms that the CAGR will be almost 30% over the next four years. Projections for the environmental sector remain positive, despite the COVID-19 crisis.

The adoption of green technology and sustainable solutions and services is being driven by a growing awareness of environmental issues and by an ever-increasing number of consumers and industries using clean energy and resources.

Initiatives to address climate change by government authorities are a source of growth opportunities.

The environmental impact in the tank storage sector Figure 1. Koole's terminal in the port of Rotterdam.

Figure 2. One of TECAM’s RTO systems for emissions treatment.

Thus, the objectives of environmental technology are aligned with almost all current trends at a social, legislative and economic level. Preserving the environment is something that concerns everyone and the business world is not isolated from these demands, much less companies in the industrial sector.

In this sense, either because of their own will or legal imperative, more and more companies from different sectors are incorporating environmental technology into their processes and applications. In addition to the obvious benefits for the environment and human health, this may also result in improved energy performance, a very important aspect in industrial processes, as well as a new energy use of the waste originated in the process, contributing to a circular economy.

Other benefits include anticipation of inevitable legislative changes, which are becoming stricter worldwide, as well as good management of corporate social responsibility in an industrial sector still closely associated with bad practices that generate too much pollution.

The importance of environmental technology is clear in its numbers and expectations. According to a study by Markets and Markets, it was estimated that in 2019 environmental technology represented a value of more than US$8.7 billion, and it is estimated that in 2024 this will reach Summer 2021 12

Concerns to preserve the environment are a growing issue.

However, how does this apply to the tank storage sector?

Identified emissions and pollutants from the sector include carbon monoxide, sulfur dioxide, hydrogen sulfide, and the aliphatic or polycyclic aromatic hydrocarbons (PAHs) fraction of petroleum. All these pollutants can easily evaporate into the air during the refinery process. In the case of an incorrect selection of storage tanks, these contaminants would leak into the soil, changing its chemical composition and resulting in enormous biological impacts. Furthermore, it would be very difficult to identify residual oil spilled into the environment.

This would imply air pollution, economic costs, illnesses and associated costs for health care, loss of productivity, etc.

Therefore, it is necessary to take advantage of synergies between human activities for the preservation of natural resources for future generations.

Apart from leaks or spills, in the storage of hydrocarbons the evaporation of hydrocarbons and their products in aboveground storage tanks is also a problem. Storage tanks also release some toxic hydrocarbons such as natural gas (methane) and other volatile organic compounds (VOCs).

Evaporation also results in a loss of economic potential.

When released into the air, all of these toxic chemicals can cause health problems such as carcinogens, reproductive problems and respiratory complications. However, environmental technology can offer different solutions for the tank storage sector.

Case studies Speaking of combining environmental technology and the tank storage sector is not theorising in a future framework, but a reality already alive in the present. For example, environmental technology was implemented at the Koole Tankstorage Minerals company in the port of Rotterdam, the Netherlands. The project, which was carried out by TECAM, prevented 693 t of VOCs from being emitted into the atmosphere during the first year of functioning. Thus, during the useful lifecycle of the terminal, almost 14 000 t of VOCs will be saved.

Koole Tankstorage Minerals is an international tank storage company. In its 101 tanks, the company stores products such as vacuum gasoil, fuel oil and clean petroleum products (gasolina, naphtha, diesel and gasoil). The company focuses on logistic and storage solutions for refineries and dealers of petrochemical products, oils and other chemicals.

In this environmental project, the emissions generated during gas venting were reduced by 99.9%. Koole needed to eliminate the vapours and odour generated while barge and ship

offloading for tank farm filling purposes with fuel oil, vacuum gasoil and class-3 blend components. These vapours contained highly polluting particles. The vapour flow and VOC content of the emissions to be treated were not constant and both the flow rate and VOC load were subject to frequent changes.

The technology solution proposed by TECAM was a custom-made RTO system. The system is adaptable to variable air flows (low, medium and high) and it treats a wide range of pollutants. It also has low operation and maintenance cost, provides high termal efficiency, generates no waste, and there may be some heat recovery for external processes.

The assembly and commissioning process for the project was carried out within nine weeks without interrupting the terminal operability at any time. The equipment guarantees the customer a life cycle without any installation problems for more than 20 years.

Another example of improvement in this scope is in BP’s exploration and production business, where steam recovery systems were recently installed in large crude oil tank loading facilities in Alaska and Scotland. BP’s refining and marketing operations have installed vapour recovery systems at many gasoline distribution terminals. As such, it is possible to obtain an additional benefit from the vapour recovery facility at retail automotive fuel refuelling sites that reduce VOC emissions during automotive refuelling by up to 90%.

When a tank storage company incorporates environmental technology, it demonstrates a social and environmental commitment, and it stands to benefit from energy efficieny and savings.

Global objective Institutions and governments are strongly promoting emission reductions in all economic areas. As an example, the UK has set ambitious targets for reducing emissions and pollutants. According to the Climate Change Act of 2008 and the fifth carbon budget, which covers the period 2028 – 2032, the UK government has set a target for a 57% reduction in greenhouse gas emissions by 2030 compared with 1990. The goal is that by 2050 all greenhouse gas emissions will be zero. In practical terms, this means changes in power generation, industrial processes, transportation, buildings and heat. With only three decades ahead to achieve that goal, it is necessary to highlight the role that all companies in the global tank storage sector have to play to achieve a common objetive worldwide.

Towards a more sustainable and efficient future The tank storage sector plays an essential role in the daily life of all citizens. After all, this is the industry responsible for the export, import and storage of essential liquids and fuels for society.

Reducing emissions will require cooperation and investment from all the actors involved: governments, companies, supply chains, consumers and other stakeholders.

Thus, the sector has to play a role in this environmental challenge.

It is essential that the tank storage sector achieves its sustainability objectives.

Saskia Huber, Linde, Germany, evaluates the changes faced by the tank storage sector at every level.

A

ccording to analysts, the global worldwide oil storage market was valued at US$3.6 billion in 2019 and is forecast to grow at a rate of over 4.4% between 2020 to 2027.1 There are several drivers fostering this growth – from rapid expansion of the oil and gas sector globally, owing to increased demand from various industry verticals such as chemical, automotive, and pharmaceutical, to the very considerable demand for increased storage capacity due to the COVID-19 pandemic.

The International Energy Agency (IEA) reported that the daily demand for crude oil worldwide grew from 96.2 million bbl in 2016 to around 100.6 million bbl in 2019.

Summer 2021 14

Likewise, global natural gas production increased 3.3% in 2019 from the previous year, with 4088 billion m3 generated.1 Continuously rising energy demand, together with other factors such as increasing natural gas production, fluctuating oil prices, and soaring government expenditure in oil and gas projects, are positively impacting global oil storage market dynamics.

Growing oil and gas activities have also contributed significantly to increased demand for water storage systems.

Global oil storage market size tends to be divided into North America, Latin America, Europe, Asia Pacific, and the rest of the world, with Latin America, the Middle East and

Africa currently accounting for the majority of the market share, and likely to maintain their positions in the coming years. Increasing oil and gas exploration and production activities, coupled with the strong presence of industry vendors, are fuelling regional market growth.1 Meanwhile, the Asia Pacific market is anticipated to demonstrate strong growth during 2020 – 2027, owing to a spike in demand for crude oil and gas, as well as growing investment in onshore and offshore oil operations across emerging economies such as India and China.1 The production, storage, refining, and distribution of crude and its derivative products call for a range of different types

and sizes of storage tanks. While smaller bolted or welded tanks might be ideal for production fields, larger welded storage tanks tend to be required for distribution terminals and refineries across the globe, with product, operating conditions and storage capacities influencing the design and manufacturer selection process.

Storage tanks can be fabricated to almost any size and shape, with certain applications requiring horizontal or even spherical designs, with the most common shape being the vertical, cylindrical storage tank. Such tanks can range from around 3 m dia. (approximately 10 ft) to over 126 m dia. (412 ft) for some of the largest floating roof tanks ever constructed, 1 15 Summer 2021

with gross capacities ranging from 100 bbl to over 1.5 million bbl for a single storage tank.

Refineries consist of a complex array of storage tanks, other pressure vessels, piping, structural carbon steel, and other components – primarily constructed from carbon steel – that depends on welding for its structural integrity. There are literally miles and miles of welds that go into the makeup of a refinery, and due to the potentially hazardous nature of the products, the welding techniques employed need to guarantee safety, resilience, longevity and cost-effectiveness.

Tank production construction The type of manufacturing method for a storage tank depends on the size of tank required and will be dependent on the type of product being stored, the location and space available for storage, prevailing weather conditions, and environmental considerations.

The earliest storage tanks used by the petroleum industry were constructed from various types of wood and riveted tanks dating back to the early 1900s, and can still be found around the world, with some surprisingly still in service.

However, ongoing maintenance costs and increasingly stringent environmental legislation – with potential penalties for non-compliance – dictate that older riveted tanks be replaced with new, state-of-the-art storage tanks. While bolted tanks are still used, especially for smaller quantities, most large capacity storage tanks are welded.

Welded refinery storage tanks are either ‘shop welded’ or welded onsite – with the size and capacity of the tank determining the method used. Typically, the decision is made by the feasibility and method available of transportation used to transfer the shop-built tank to its final location. Pre-tested for leaks, it is generally ready for use once it arrives on site.

Unprecedented need for more storage

Figure 1. Linde has developed a torch which lowers the barriers to entry when it comes to plasma arc welding.

Figure 2. Welded refinery storage tanks are either

'shop welded' or welded onsite, with the size and capacity of the tank determining the method used.

Summer 2021 16

In the 1980s, the world concerned itself with what to do if it ran out of oil. Today, however, we are witnessing an alternative perspective, with a surplus of oil, but not enough storage. Last year, oil storage briefly became a commodity that was more valuable than oil itself.2 The global public health crisis brought on by COVID-19 resulted in industries across the globe essentially shutting down operations, with many governments imposing restrictive measures on the daily lives of billions of people in an effort to slow the spread of the coronavirus.

The pandemic put on hold much of the world’s economy, closing factory gates, grounding aircraft, and leaving cars and other vehicles stationary for months at a time. In doing so, it dramatically reduced the need for fuel, leaving the world awash with oil supplies. From a storage perspective, massive storage tanks in places such as Rotterdam in the Netherlands, Trieste in Italy, and the UAE quickly filled to capacity.

Oil producers, refiners and traders found themselves turning to more unusual locations to store oil including ships, railcars and unused pipelines as more conventional storage facilities become scarce.

Rising sea storage is usually an indicator of reduced availability of onshore storage tanks, as it is more expensive and is more technically complex. However, in 2020, just off the coasts of Texas, US, and Scotland, there were over 80 tankers – each holding up to 80 million gal. filled with oil.3 Salt caverns in Sweden and other Scandinavian countries became full.4 The economic shocks from the current coronavirus pandemic are likely to last for some time and oil producers cannot simply shut off the tap, meaning that reduced oil demand may continue. Although coronavirus lockdowns in some parts of the world are coming to an end, extra storage capacity is likely to continue to be in high demand.

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The great crew change Using a term well recognised within the oil and gas industry, the ‘great crew change’ refers to the challenge faced by employers to replace those skilled employees that are reaching retirement age. The situation among fabricators is no different. Welding operators of the baby-boom generation are reaching retirement age while fewer people are choosing careers in welding. The American Welding Society (AWS) estimates there will be a shortage of nearly 400 000 welding operators in the industry by 2024.5 The shortage is being felt across all sectors of welding – from fabrication and construction to manufacturing. For employers, this can mean missing deadlines or productivity targets, a reduced ability to take on more work, or cost increases in the operation due to added rework and scrap stemming from less-experienced welding operators.

Struggling to find enough welders to fill open jobs is one obvious impact. Another challenge for employers is the lack of experience of new welding operators coming into the trade.

Beyond the first step of finding qualified employees, companies then must train them to ensure they are properly prepared to weld in a manufacturing environment. This training can be a lengthy process and requires investing additional time, money and effort.

Both of these factors impact a company’s ability to remain competitive by completing projects on time while maintaining a high quality, as well as their ability to grow and take on more work.

Advancements in technology can help fill this gap. Welding equipment manufacturers are stepping up with a variety of solutions that can help companies address the welding operator shortage.

Reinventing plasma arc welding Plasma arc welding (PAW) is an extremely productive, high-quality welding process, typically deployed for quality-critical applications where reliable outcomes are essential. It is also a popular welding process for exotic materials, such as high-alloyed steels and titanium.

PAW bears many similarities to tungsten inert gas (TIG) welding, with both forming an arc of highly ionised gas (plasma) between a pointed tungsten electrode and the workpiece.

However, in PAW, the electrode is positioned within the body of the torch, which means plasma can then be fed through a nozzle, constricting the arc and forcing the plasma out at a much higher speed and temperature – upwards of 20 000°C (50 000°F). The more concentrated arc energy allows welding in a single run and without filler metal, providing faster travel speeds with total and uniform penetration. This is useful for quality-critical applications in the oil and gas industry where reliable outcomes are vital.

However, adoption rates of PAW have remained low because PAW is still often viewed as a complicated, sophisticated technique that requires a high level of skill and experience on the part of the welder. With conventional plasma torches – which have not changed much since the 1970s – the preparation and assembly is complex, time-consuming and prone to error. The welder must align and adjust the electrode to a very specific height, grind the electrode, orient the nozzle correctly, and ensure the right mixture and flow of gases.

Summer 2021 18

With such complexity comes a high chance of variation, and therefore a reduced reliability and repeatability. While highly-skilled and specialised welders are capable of reducing the variation in their setup, such welders are becoming increasingly difficult to find. Consequently, many manufacturers and welding engineers opt for simpler techniques even in cases where PAW would be the better choice.

Linde has developed a torch called the the ARCLINE® PAW, which lowers the barriers to entry when it comes to PAW, and delivers the benefits of speed and weld quality but without the drawbacks of complexity at set up.

The fail-safe intuitive design means that the torch can be assembled in just 15 seconds, without the need to adjust electrodes, and its one-click bayonet allows for precise attachment of consumables. Its cooling action also means that those consumables last longer and require fewer replacements. The torch gives precise, robust and stable performance for spatter-free welds and improved repeatability, resulting in less re-work. This is particularly important for manufacturers of storage tanks, as bottlenecks at welding stations create the problems of material build-up at one end of the production process, with little happening at the end stage. As well as delivering greater productivity, the novel features combine to bring the advantages of plasma welding to fabricators that are experiencing the loss of more experienced PAW welding operators.

ÖMV: a case in point In 2019, Swedish process equipment manufacturer, ÖMV, was the first company in the world to benefit from this new technology. With the company manufacturing advanced process equipment such as reactors, heat exchangers and storage tanks for the refining industry, it understands the need for superior welding for quality-critical applications. The company understands that there is no room for error in the welding process, and it has used plasma welding for many years as it is a reliable welding method for challenging applications. Nevertheless, ÖMV was looking for a better method for welding titanium, which had been causing the torch heads on its old plasma welders to overheat, resulting in the welding operator having to switch nozzles and adjust the settings for every new weld.

Conclusion The global oil storage market has been facing a catch-22: the urgent requirement for increased storage capacity, but a dwindling skilled workforce able to manufacture the storage tanks needed. But as in so many cases of manufacturing dilemmas, it is technology innovation that will lead the way out.

References 1.

2.

3.

4.

5.

'Global Oil Storage Market Size to Register 4.4% CAGR Through 2027', Market Study Report LLC, (2020).

DUNN. K., 'Crude math: Why $10 oil could be worth less than nothing', FORTUNE, (2020).

REED, S., 'The World is Running Out of Places to Store its Oil', The New York Times, (2020).

BUSSO,R., KELLY, S. and SANICOLA, L., 'Ships, Trains, Caves: Oil Traders Chase Storage Space in World Awash with Fuel', Reuters, (2020).

'Welding Shortage Fact Sheet', American Welding Society (AWS), (2015).

J. Randolph Kissell, Trinity Consultants, USA, solves a cold case, and outlines how to size wind girders for tanks of any diameter.

C

ylindrical aboveground storage tanks are very efficient at resisting hydrostatic pressure caused by the liquid they store, which puts the cylindrical shell in tension.

Conversely, cylinders are less effective in resisting external pressure from wind, which places the shell in compression that can cause buckling. Tank design standards such as API 650 have long required that shell buckling strength be compared to these compressive stresses, and that stiffening rings (called wind girders) be provided when the shell would buckle without such stiffeners.

Storage tanks without fixed roofs, called open top tanks, always require a wind girder near the top of the shell to resist buckling from the wind. Tanks with fixed roofs and open top tanks sometimes require a stiffening ring between the tank bottom and the tank top; such rings are called intermediate wind girders. The maximum distance between stiffened points (the tank bottom, a wind girder, or a fixed roof) was established by buckling theory for cylinders developed in the 1930s.

McGrath adjusted the theory to address cylinders with varying thickness over their height and incorporated this into API 650 in the 1960s. The resulting 650 equation relating shell thickness (t), unstiffened shell height (H), tank diameter (D), and horizontal wind pressure (PWS) is well documented: Pws =

2.1 E ( H/D)( D/t) 2.5

(1)

Conversely, the origin of API 650’s wind girder size requirement is murky, based on an unpublished 1929 paper by Boardman, who proposed that the bending moment in the wind girder caused by wind on the tank shell is: M = 0.01PWSHD2

(2)

He noted that: “This formula has not been derived […] but at least its form has been shown to be logical”. Nonetheless, as far as estimates go, it was a fortunate one because it worked for tanks of that day. But as tank diameters

1 19 Summer 2021

increased, the estimate seemed to become extremely conservative. In 2016, API 650 was revised to limit the diameter term in this requirement to 200 ft, regardless of the actual tank diameter, codifying an informal practice used since the 1970s.

Many have tried to explain this, only to be reduced to hand waving. What seems especially counter intuitive is that API 650 states that the top wind girder’s section modulus is strongly dependent on tank diameter, increasing with the diameter squared for tanks up to 200 ft dia., but not for tanks over 200 ft dia.. For example, if API 650’s rule for tanks under 200 ft was applied for a 300 ft dia. tank, the wind girder Table 1. Maximum external shell wind pressure section modulus should be (300/200)2 = 2.25 times the size coefficients, H/D = 0.5 (+ is inward) 650 requires. This is way beyond what safety factors cover.

Tank top External pressure coefficient Cp Furthermore, the section modulus for intermediate wind girders has no such limit; it is required to increase with tank Windward 90˚ to wind Leeward Average Net radial horizontal diameter for all diameters.

Yet API 650’s apparently irrational wind girder Open 1.75 -0.2 0.4 0.51 0.56 requirements have worked. Tanks rarely collapse under wind Closed 1.0 -1.0 -0.4 -0.26 0.55 pressure, even during hurricanes and tornadoes. Of course, this might mean that the requirements are very conservative, or that experience with tanks over 200 ft dia. is too limited to draw conclusions regarding the validity of API 650’s rule. As demand grows for tanks with greater capacities, however, understanding how wind girders should be sized becomes more urgent. A rational explanation for this paradox is, however, finally available.

Wind girder loading

Figure 1. Plan view of tank shell wind pressure for open and closed top tanks.

Figure 2. Open top shell wind pressure.

Figure 3. Wind pressure vs height on an open top tank shell.

Summer 2021 20

In his 1988 wind tunnel study, MacDonald measured the wind pressure distribution for tanks with a height to diameter ratio (H/D) of 0.5, typical of a 100 ft dia. tank, as shown in Figure 1 and summarised in Table 1. Positive pressure acts inward on the shell; negative pressure acts outward.

MacDonald also showed that the wind pressure distribution around the tank circumference depends on the tank’s H/D ratio. As this ratio decreases (as tank diameter increases, H/D decreases because tank height is typically about 50 ft for all tank diameters), the ovalising effect of the wind on the shell decreases slightly. This is because the outward suction of the wind at roughly 90˚ to the wind direction decreases in magnitude and extent as illustrated in Figure 2.

H/D ratios of typical open top tanks vary from approximately 1 (a 50 ft dia. x 48 ft tall tank) to 0.2 (a 300 ft dia. x 48 ft tall tank). A 200 ft dia. x 48 ft tall tank has H/D = 0.24, which is less than the smallest H/D ratio investigated by MacDonald. Although MacDonald did not investigate tanks with H/D ratios less than 0.5, his data suggest that as the H/D ratio decreases, the extent and magnitude of the suction portion of the shell perpendicular to the wind decrease. Regardless of the H/D ratio, however, the windward and leeward wind pressure coefficients are approximately the same: about 1.8 and 0.4 (both inward) respectively.

MacDonald’s study showed that wind pressure also varies over the tank height, as shown in Figure 3. The average wind pressure on the top half of the shell is approximately 93% of the maximum wind pressure.

Because wind causes pressure, it acts perpendicular to the tank shell. Therefore, wind girders are ring beams with transverse distributed loads. These distributed loads can cause moments, shears, and axial forces in the girders, but the moments cause the significant stresses.

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Wind girder forces Moments, shears, and axial forces in a circular ring can be determined by combining cases that have been solved using Castigliano’s second theorem. Many such cases are tabulated in Roark’s ‘Table 17’. This approach can be used to approximately derive Boardman’s guess, which is API 650’s current provision, by combining Roark case 8 for a uniform lateral pressure and case 20 for tangential shear.

The resulting maximum moment in the wind girder due to a uniform horizontal distributed load w over the tank diameter D is: M = 0.14wR2 = 0.035wD2

(3)

Figure 4 shows the moment in the ring using this method for a 100 ft dia. x 48 ft tall tank with 11 psf wind pressure.

The moment thus calculated varies in sign around the circumference, as shown in Figure 4, causing compression at the

outside of the wind girder at some points on the circumference (approximately the portion 40˚ to either side of the wind direction on the windward side and 40˚ to either side of the wind direction on the leeward side) and tension at the outside of the wind girder in the areas perpendicular to the wind direction.

The upper portion of the shell is stiffened against buckling by the top wind girder and the lower portion of the shell is stiffened by the tank bottom. To determine the portion of the shell over which the wind girder resists the wind pressure and thus the distributed load w that acts on the wind girder, the shell can be divided into upper and lower portions by considering its buckling strength. Tanks are typically constructed of 8 ft tall constant thickness courses of decreasing thickness toward the top of the shell. Because the equation for shell buckling strength is based on a shell with the same thickness from bottom to top, the shell height H in the shell buckling strength equation must be adjusted to account for this.

API 650 calls the adjusted shell height the transformed shell height Htr. Because API 650 uses the smallest shell course thickness in the shell buckling strength equation, the height of each shell course thicker than the least shell thickness is adjusted downward to determine the transformed shell height. API 650’s transformed shell height is the height of a shell with the least thickness used in the shell that has the same buckling strength as the actual shell:

Figure 4. Moment in a circular ring under uniform projected wind pressure.

Figure 5. Transformed shell height.

As shown in Figure 5, the wind girder supports the top half of the transformed shell height and the tank bottom supports the bottom half of the transformed shell height against buckling.

The transformed shell height is always less than the actual shell height because the transformed height of shell courses thicker than the least shell thickness is less than their actual height. For example, for a 200 ft dia. x 48 ft tall tank designed for a product specific gravity of 0.8, the transformed shell height is 18.22 ft.

API 650’s current provisions assume that the top ¼ of the actual shell height H equals ½ the transformed shell height, in which case w = PWSH/4. This can be demonstrated by substituting PWSH/4 for w in equation (3), giving a wind girder moment: M = 0.14wR2 = 0.14(PWS H/4)(D/2)2 = 0.00877PWSHD2 ≈ 0.01PWSHD2

Figure 6. Wind girder moment from varying wind pressure around the tank circumference.

Summer 2021 22

(5)

API 650 uses this moment to determine the required section modulus S by limiting the bending stress it causes (M/S) to the wind girder’s yield strength. This wind girder moment estimate is approximate because it only models the net horizontal wind pressure without accounting for pressure variation around the tank circumference and assumes that half of the transformed shell equals a quarter of the actual shell height for all tanks. For a 200 ft dia. tank, half of the transformed shell height is (18.22 ft)/2 = 9.11 ft, only 19% of the actual shell height.

The pressure distribution given in Figure 1 gives a different maximum wind girder moment than the average

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Unsurprisingly, Figure 7 shows that moment in the wind girder depends on the wind pressure distribution.

The more precise wind distribution has a greater maximum moment (96.1 ft-k) than the projected uniform distribution (46.3 ft-k). Comparing the maximum moment for both distributions, which occurs at the centre of the windward side, shows that the maximum moment in the wind girder is:

Figure 7. Wind girder moment from uniform and varying pressure distributions.

Figure 8. Wind girder size by current and proposed rules. horizontal pressure. To determine the moment from the actual pressure distribution, four Roark cases were combined, as shown in Figure 6.

The resulting moments are shown in Figure 7 and compared to the moment distribution from the uniform projected pressure shown in Figure 4.

M = 0.14(96.1/46.3) wR2 = 0.28wR2 = M = 0.28PWS(Htr/2)(D/2)2 = 0.035PWSHtrD2

(6)

The approximation that the wind girder supports the top ¼ of the shell height is reasonably accurate for tanks under 200 ft dia., but overly conservative for tank diameters over 200 ft. For large tanks, lower shell courses are much thicker than the minimum shell thickness, and the transformed shell height is short. By eliminating this approximation, the empirical rule that wind girders for tanks over 200 ft dia. need not be larger than wind girders for a 200 ft dia. tank can be eliminated without requiring significantly larger wind girders. Figure 8 compares wind girders using the current and proposed rules.

Conclusion API 650’s current requirement for wind girder size is empirical and becomes inaccurate for tanks over 200 ft dia. By revising it as outlined in this article, the requirement is made rational and accurate. This cold case has finally been solved.

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Bruce Kaiser, Lightning Master, USA, outlines two different approaches to storage tank grounding.

W

hen designing a lightning protection grounding system for production/disposal of storage tanks, there are the two main sources of guidance: the American Petroleum Institute (API) recommended practices (RP) 2003 and 545, and the National Fire Protection Association (NFPA) standard NFPA 780. It should be noted that, although it provides lightning protection system design guidance specifically for tanks, the API 545 committee has been disbanded, and the RP rolled into other API documents. However, it remains a useful source of information.

2 25 Summer 2021

There are two different, and not always convergent, schools of thought that have produced two different standards or recommended practices regarding the grounding of production and storage tanks, as well as other flat-bottom steel tanks. Both approaches will be examined in this article.

It should be noted that both standards recommend the minimisation of flammable vapours and gases as a primary means of controlling ignition, and caution that grounding for purposes other than lightning protection should be considered.

API API 2003, September 2015 edition, section 5.4.1, ‘Inherent Grounding’, states that metallic tanks, equipment, and structures commonly found in the industry that are in direct contact with the ground have proved to be sufficiently well grounded to provide for safe propagation to ground of lightning strokes. It goes on to further state that supplemental grounding by means of driven ground rods neither decreases nor

Figure 1. Typical production/disposal tank battery.

increases the probability of being struck, nor does it reduce the possibility of ignition of the contents.

Supplemental grounding is necessary, however, where direct grounding is not provided.

Ironically, the API 2003 then refers the reader to the NFPA 780 (see below) for more information on grounding practices for lightning protection. Further, API 545, A.2.2 reaffirms that a tank is considered adequately grounded if the tank bottom is resting on the ground or foundation.

A.3 states that the existence or absence of a release prevention barrier is not relevant to the prevention of lightning induced fires or explosions. A release prevention barrier is described as all barriers or combinations thereof that prevent the escape of material or channel released material for leak detection.

NFPA NFPA 780, chapter 7, addresses the ‘Protection for Structures Containing Flammable Vapours, Flammable Gases, or Liquids That Can Give Off Flammable Gases’.

Although API specifically addresses tanks, NFPA also includes other types of structures. It is important to keep this in mind when applying chapter 7 to tanks. It is also important to be aware that the chapter specifically excludes non-metallic (fibreglass) tanks.

NFPA 780, 7.3.7, addresses the grounding of all structures containing flammable vapours, flammable gases, or liquids that can give off flammable vapours.

7.3.7.1 requires a ground ring electrode or ground loop conductor supplemented by grounding electrodes for such structures. 7.3.7.2 exempts structures with a perimeter projection of 200 ft or less.

7.3.7.3 specifically addresses metal tanks and requires grounding by one or more of these methods: 1. Connection without insulating joints to a grounded metallic piping system.

2. Accepting inherent self-grounding of vertical cylindrical tanks greater than 20 ft dia. resting on earth or concrete or greater than 50 ft dia. resting on bituminous pavement.

3. A minimum of two grounding electrodes at intervals not exceeding 100 ft around its perimeter.

If the tank is installed over an insulating membrane for environmental or other reasons, either the first or third method outlined above is required (self-grounding over a containment barrier is not recognised).

Discussion

Figure 2. Supplemental grounding.

Summer 2021 26

There is a considerable gulf between the API and NFPA requirements. This may be explained by looking at the history of document development and the backgrounds of the writing committee members.

The API committee members tended to come from the owner/operators, with years of practical field experience designing, building, operating and maintaining these facilities. The NFPA committee

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members, while very experienced in lightning protection for ordinary facilities, have little or no experience with these types of structures.

Inherent self-grounding of flat bottom steel tanks Inherent self-grounding of flat-bottom steel tanks has always been part of the API lightning protection documents and is part of the NFPA 780 document, albeit with minimum diameter requirements.

Acceptance of this method of tank grounding is particularly important to production/disposal tank operators, as these tanks generally do not meet the minimum diameter requirements of NFPA 780.

Why the minimum diameter requirements?

There are tens of thousands of tanks that have been safely self-grounding for many years. The 20 ft (resting on earth or concrete) and 50 ft (resting on bitumen) requirement contained in NFPA 780, 7.3.7.3, appear to have been introduced into the 1983 edition by tank owner/operators. However, no justification for these minimum diameter requirements could be found. If owner/operators wanted to introduce a minimum diameter requirement, why was only the NFPA changed and not the applicable API documents? Indeed, discussions at an API 545 committee meeting in New Orleans, Louisiana, US, agreed not to change grounding requirements in any way, including not introducing a minimum diameter requirement.

Petroleum engineers regularly point this out when the subject of using 780 as their standard arises. They look at the NFPA 780 minimum diameter requirements vs years of successful field experience with inherent self-grounding of smaller diameter tanks and conclude that 780 simply does not understand the nature of tanks. Most are also happy to point out that the NFPA 780 grounding requirements look suspiciously similar and are more appropriate to the requirements for grounding a small, round wood barn as opposed to grounding a heavy, flat-bottom, thick wall metal structure sitting on earth. They are also quick to ask why a 4 ft2 grounding plate installed at minimum depth is adequate for grounding but not a 100+ ft2 tank bottom.

When the only solution available is a hammer, every problem looks like a nail. NFPA 780 systems are direct descendants from those designed by Ben Franklin to keep wood structures, particularly barns and houses, from burning down. This ignores the fact that a metal tank is wildly different from a wood barn.

A useful exercise in understanding the inherent grounding of flat bottom metal tanks is to consider the grounding of a non-metallic structure similar in size and configuration to a tank. If we look at a structure such as a 14 ft dia. round wood barn, according to NFPA 780, structural lightning protection would be

Summer 2021 28

installed in the form of lightning rods bonded together by a main conductor, and at least two down conductors. The down conductors could be grounded by flat metal plates, each a minimum thickness of 0.03 in. with a minimum surface area of 2 ft2 if buried greater than 18 in. below grade (NFPA 780, 4.13.5.1).

If installed at a depth of less than 18 in., the surface area of the ground plate must be increased to 4 ft2 (Underwriters Laboratories installation guideline UL 96A). This design would require that, in the event of a direct attachment to the structure, all of the lightning energy travel along two down conductors of extremely limited cross section and be dissipated to earth through two ground plates of limited size.

On the other hand, a direct lightning attachment to a 14 ft dia. metal tank would allow the lightning energy to flow down the much larger surface area of the tank shell and be dissipated to earth over the much larger surface area (615 ft2) of the tank bottom. The short duration, high energy portion of the strike would tend to be dissipated to the ground around the perimeter of the tank bottom (analogous to shunts on an external floating roof [EFR] tank), with the longer duration, lower energy portion of the strike spreading across the tank bottom (analogous to bypass conductors on an EFR tank). This is why flat bottom metal tanks are considered to be inherently self-grounding. It is much larger in surface area than a flat grounding plate and is pressed downward on the earth with thousands of pounds of weight of the tank and the stored product.

NFPA 780, Annex B.4.3, states that properly made ground connections are essential to the effective functioning of a lightning protection system, and that every effort should be made to provide ample contact with the earth. This does not necessarily mean that the resistance of the ground connection should be low, but rather that the distribution of metal in the earth or upon its surface in extreme cases should be such as to permit the dissipation of a stroke of lightning without damage.

Many newer production/disposal sites are surrounded by metal wall containment systems. These systems constitute an attractive solution in that they may become part of the site bonding/grounding system. If they form a continuous steel wall around the site and otherwise meet the requirements of NFPA 780 they may be used as a conductor/grounding system.

Summary Two different results deriving from two different approaches to grounding have been presented. The API documents were written to specifically address tanks, whereas the NFPA 780 was written to address a variety of structures. Therefore, the API appears to be the go-to document for tank grounding. However, the NFPA 780 offers much more detail covering the design of structural lightning protection, meaning that a combination of both documents may be in order.

Jim DeLee and Richard Koeken, Fluid Components International, USA, discuss the importance of thermal flow meters for safety-critical nitrogen tank blanketing.

M

arine tanker terminals and their frequently adjoining refineries rely on nitrogen gas tank blanketing to maintain a safe operating environment as oil/gas products are transported, processed, stored and distributed for use. Nitrogen blanketing is a practice commonly used in the chemical and petroleum refining industries to reduce the hazards associated with flammable liquids, which improves the safety in the plant and can help increase productivity.

The ‘blanketing’ or ‘padding’ is a process of applying inert nitrogen gas to the vapour space of a tank or vessel. This precautionary step minimises the possibility of an explosion or fire by reducing the oxygen content or the concentration of flammable and/or explosive vapours in a tank or vessel with inert nitrogen. In concentrated marine terminal, refinery and storage areas, safety is critical to prevent large scale fires and explosions.

Furthermore, blanketing also helps decrease product evaporation and protects the tank from structural corrosion damage caused by air and moisture. Nitrogen usage varies

based on the size of the tanks and vessels used in the production, transfer, transportation and packaging of the product.

There are several common types of blanketing: continuous purge, pressure control and concentration control. The continuous purge method employs a constant flow of nitrogen. This approach is simple, but nitrogen consumption is high. The pressure control and concentration control methods are more costly to implement and rely on the pressure in the tank or the concentration of the oxygen to initiate the flow of nitrogen, but these methods improve overall safety and the efficiency of the process. Fluid Components International’s (FCI) mass flow meters are used in all three of these types of purging methods.

Challenges Terminal and refinery engineering teams are generally concerned with measuring the flow rate of nitrogen accurately and dependably in their tank blanketing operations. The blanketing process is important in tank storage applications

2 29 Summer 2021

due to the possibility of static electricity build up, and the nitrogen displaces one leg of the fire triangle. Implementing the pressure control system satisfied the plant team’s major concern, which is always safety first.

The consequences of a major accident at a marine terminal and adjoining refinery have the potential to result in a major loss of life, destruction of expensive equipment and damage to nearby populations and communities. In addition, the shutdown of such a facility can have a crippling effect on any region where energy supplies are tight or where there are limited additional supplies. Beyond these consequences, a prolonged smoky fire has the potential to cause further harm to the environment through global warming and the run-off consequences of stored petroleum fluids can cause major harm to marine life in the area.

Any time combustible, flammable or explosive materials are stored, processed or generated, the use of nitrogen tank blanketing helps to prevent these materials from coming into contact with oxygen in the air. The inert blanket of nitrogen gas creates a non-flammable environment, which prevents the

possibility of fire or explosion, and therefore provides protection to nearby people, equipment and entire facilities.

The other reasons that port teams want more accurate gas flow measurement are to improve efficiency, to lower the plant’s nitrogen consumption and costs, and to eliminate any unexpected supply shortages. After facility safety to protect people and equipment, controlling facility consumables costs is always a top priority in any business.

The quantity of nitrogen pumped into or released out of the tank’s vapour space is controlled by a predetermined pressure set point. When product is pumped from the tank, the vapours inside expand and the pressure falls below the set point, and additional nitrogen is then introduced. As the tank is filled, the vapours begin to compress and the nitrogen vapours are released and usually sent to a vapour recovery system. In practice, it is demonstrated that there can also be minor leakages in the nitrogen blanketing system, reducing the pressure in the vessel over time. When the pressure falls below the set-point, a small top-off nitrogen flow is introduced in the vessel to increase the pressure above the set-point.

When tank product falls and rises, it can create static electricity. Therefore, the amount of nitrogen in this vapour space is an extremely important safety factor. Typically, oil/gas marine ports and refineries require a flow meter that can provide a mass flow output, measure a low flow rate of 1 – 17 normal m3/hr (36 – 600 standard ft3/hr) at 70°C (158°F) with a pressure maintained at 5 bar(g) (60 psig) in a 25.4 mm (1 in.) schedule 80 pipe with limited straight-run. With these process requirements, the gas flow meter choices available narrow to some degree.

Solutions Typically, the engineering team at an oil/gas marine terminal or adjoining refinery will need to work with a flow meter manufacturer’s application engineering team to consult on their specific tank blanketing needs. Discussions will include any specific problem issues or goals and then review a facility’s overall operating environment.

After completing this process with FCI, the team at a large terminal chose the model ST100AL thermal dispersion air/gas in-line mass flow meter and the Vortab® flow conditioner with an accuracy of +/-0.75% of reading, +/-0.5% of full scale with a maximum of 5% of reading. This flow meter is an inline, spool piece gas flow meter for industrial process and plant Figure 1. Thermal dispersion principal of operation. applications, which combines good transmitter/electronics and calibration with a built-in flow conditioner and a standard turndown ratio of 100:1 (optionally 1000:1).

The integral Vortab flow conditioner provided a low-pressure loss solution for flow profile irregularities produced by elbows, valves, and other disturbances that are commonly present at terminals and refineries. When sufficient pipe straight run is not available to generate the necessary flow profile, the flow conditioners combine proven swirl removal technology with a unique mixing process to achieve efficient flow Figure 2. Nitrogen tank blanketing process on refinery tanks. conditioning.

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Tabs are located strategically within the conditioner. They promote rapid mixing that creates a uniform flow profile for proper meter flow measurement by eliminating swirl and distortion or any other profile irregularities that could be present through the transitional flow range (Reynolds’ Number 1000 – 4000).

The ST100AL flow meter is factory calibrated in FCI’s NIST and ISO17025 traceable calibration laboratory for nitrogen service. The laboratory includes multiple calibration stands and is capable of calibrating in virtually any other process gas as well as mixed gases or fluid-entrained gases.

Once installed, the use of a thermal flow meter provides the accurate, repeatable and reliable output under all flow conditions (low flow during top-off flow and high flow during re-filling of the vessel) necessary for the tank blanketing system to operate as designed and to provide the safety and cost savings expected in this application.

The ST100A insertion style air/gas meter has the same accuracy specifications as the ST100AL, but allows the end user the capability to insert the probe directly into the line.

This provides a solution for applications with larger lines.

Up to five calibration groups can be stored to support a broad flow range, differing same gas mixtures, multiple gases, with a flow range of 100:1 (optionally 1000:1). An on-board data logger is included with a removable 2 GB micro-SD memory card to store process flow data.

Users may select from three 4 – 20 mA analogue outputs, frequency/pulse, or certified digital bus communications such as HART, FOUNDATIONTM Fieldbus, PROFIBUS PA or Modbus RS-485 ASCII/RTU. Should a plant’s communication need to change in the future, the ST100AL meter can be fitted with a replacement card that can be installed by technicians in the field.

For ease of local on-site data view, the meter also features a graphical, multivariable, backlit LCD display/readout. It provides local information with a continuous display of all process measurements and alarm status, as well as service diagnostics.

Designed for rugged industrial applications, it operates at up to 125°C (257°F) and is available with both integral and remote (up to 300 m [1000 ft]) electronics versions. The entire instrument is SIL 1 compliant (IEC 61508) and has been agency approved for hazardous environments. The enclosure is NEMA 4X/IP66/IP67 rated. Ex approvals include FM, FMc, ATEX Zone 1/21, IECEx Zone 1/21, INMETRO (Brazil) and EAC/TRCU 12/20/32.

Thermal dispersion sensing

Figure 3. Marine terminal with petrochemical, refining and storage tanks.

Mass flow meters such as the ST100AL are designed with rugged and reliable thermal dispersion sensing technology, which provides direct mass flow measurement. This technology places two thermowell protected platinum RTD temperature sensors in the process stream.

One RTD is heated while the other measures the actual process temperature. The temperature difference between these sensors is varying or maintained based on the media cooling effect. FCI thermal dispersion flow meters can provide mass flow rate measurement without the need for additional pressure or temperature transmitters (Figure 1).

With direct mass flow sensor technology, the thermal flow meters also include built-in real-time temperature compensation, which ensures repeatable measurement even in applications where wide process seasonal temperature variations are present, such as in some marine terminals in continuous operation throughout the year (summer and winter).

With no moving parts or orifices to plug, foul or wear, thermal mass flow meters are virtually immune to dust and dirt. The instruments are almost maintenance-free.

Conclusion

Figure 4. Model ST100AL thermal mass flow meter with Vortab flow conditioner.

Summer 2021 32

ST100AL flow meters have been installed in marine terminals around the globe in multiple nitrogen tank blanketing applications. The flow meters provide accurate mass flow measurement with limited straight run, which provides a safe environment in the processing, storing and generating of their flammable and combustible products.

Multiple terminal and refinery operators have also reduced their nitrogen consumption considerably, which in turn reduced their overall operating costs of consumption.

Tai Piazza and Greg Tischler, VEGA Americas, USA, present two case studies to emphasise the importance of being able to isolate instrumentation on a valve and still receive reliable level measurements.

H

igh-value processes are found everywhere in the chemical industry. Massive storage vessels hold volatile yet precious chemicals, and base ingredients move through complex continuous processes to create all-important chemical components. In both scenarios – and everywhere in between – the ability to isolate instrumentation on a valve and still receive accurate and reliable level measurements is key to safe, continued operation.

Two chemical plants with very different processes on opposite sides of the US were dealing with similar level measurement dilemmas: unreliable, high-maintenance instrumentation in processes that are costly to take offline.

Both facilities consequently employed the VEGAPULS 64.

They mounted the radar sensor on complex process connections, and it did not interfere with their measurement, due to the sensor’s 80 GHz technology.

Measuring in tight spaces High frequency radars for level measurements have several benefits, but when it comes to mounting on more complex process connections such as ball valves and knife gate valves, a highly-focused signal and narrow beam angle are important. A radar’s beam angle is determined by two factors: antenna size and transmission frequency. Both factors are inversely proportional to the radar beam. A larger antenna or a higher frequency will emit a tighter signal.

An 80 GHz radar sensor with a 3 in. antenna has a beam angle of less than 4°, enabling the sensor to emit an uninterrupted signal past the many reflective surfaces and tight spaces found within a ball valve. Additionally, when more of the radar signal’s energy reaches the product surface below, the radar antenna will receive a stronger return signal to provide a more reliable measurement – even when it is measuring a product with poor reflective qualities.

33 Summer 2021 3

Figure 1. High frequency 80 GHz radar technology has allowed users to mount radar level sensors on increasingly complex process connections without sacrificing reliable, accurate measurements.

areas, butadiene vapours can accumulate, displace oxygen, and lead to asphyxiation. To complicate matters even more, each sphere is continuously receiving off gases from other units, meaning that they are constantly being filled, requiring fine process control.

The Gulf Coast facility could not achieve the level of process control that it needed with its current level measurement instrumentation – a 26 GHz radar sensor. The radar sensor would only receive a weak return signal at best because of butadiene’s poor reflective properties. With an unreliable measurement, operators needed a better solution.

This type of measurement conundrum is typically resolved by adding a stilling well to the vessel. The stilling well helps to focus the radar signal straight down to the surface of the product and direct more of the return energy to the radar antenna. A stronger return signal provides a more reliable measurement. However, the lengthy shutdown and excessive construction costs required for this solution make it unreasonably expensive.

Fortunately, a radar sensor with a higher frequency and resultant smaller beam angle could provide a more accurate and reliable measurement with a simpler, more cost-effective installation. Installers mounted and calibrated an 80 GHz VEGAPULS 64 on a double ball valve block and bleed assembly without having to drain the massive vessel or take it out of service. A measurement through this complex process connection is only possible because of the radar’s high frequency, small beam angle, and improved sensitivity.

A sticky, messy process

Figure 2. Radar level sensors using a lower 26 GHz

frequency (left) lose their signal on the multiple surfaces within a ball valve. High frequency 80 GHz radar sensors (right) use a more focused beam angle, which enables the sensor to make a measurement through complex valves.

The VEGAPULS 64 has a high dynamic range, or sensitivity. The added sensitivity allows the radar sensor to output an accurate level measurement. This article will discuss the use of this technology in three different scenarios at two different chemical facilities.

A block and bleed valve for liquid gas storage Along the Gulf Coast is one of the US’ largest oil and gas producers and petrochemical manufacturers. Storage tanks scatter the landscape, containing a variety of hydrocarbons, petrochemicals, and raw material chemicals. These vessels come in all shapes and sizes, but a group of massive 40 ft spheres stands out.

These spheres hold liquid butadiene, an important monomer used in the production of synthetic rubber, primarily for tyres. Butadiene’s physical properties make it a significant fire and explosion hazard, and in poorly ventilated Summer 2021 34

A chemical facility closer to the East Coast specialises in caprolactam, the primary feedstock in the production of nylon polymer used in carpet fibres, plastics, and films.

A single step in making this all-important product involves adding a dry powder and water to a mixing vessel, which creates a substance with a sticky, cake batter consistency.

The product inside tends to stick to any level measurement instrumentation, and regular cleaning is a necessity.

This process alone is a multi-million dollar continuous process, meaning that each maintenance shutdown is a costly endeavour. Until recently, expensive cleaning had become routine. An 80 GHz VEGAPULS radar sensor and a creative process connection saved this facility millions of dollars in lost revenue.

Operators installed a flushing ring and knife gate valve with the radar sensor mounted on top. The flushing ring shoots a burst of water on the face of the sensor to keep it clean. In instances of extreme buildup, maintenance crews can close the knife gate valve while the process continues to run, quickly clean the sensor, and return the sensor to operation. All of this is done without the huge expense of shutting down the process and draining the tank.

With other level measurement technology, pressure sensors would likely begin outputting erroneous measurements because of excessive buildup. A guided wave radar probe would have similar issues with buildup, requiring regular cleaning, but the sensor could not be isolated from the process. A non-contact radar with 26 GHz technology would lose its signal in the complex process connection, making a reliable measurement nearly impossible.

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Measuring hazardous liquids in a bridle

Figure 3. The knife gate valve isolates the 80 GHz

radar level sensor from the process, so maintenance can clean the sensor as needed without stopping the process.

Figure 4. The bright yellow non-contact radar sensor replaced an old guided wave radar. Because of its focused beam angle, it was able to reliably make a level measurement in this bridle.

Summer 2021 36

The same East Coast chemical company stores nitric acid in large vessels to use within its many processes. To monitor the acid’s usage and maintain an adequate supply, the company monitors the level in two bridles on the side of the vessel. Different technologies are used in each of these bridles to provide redundant level measurements for additional safety.

In one bridle, a magnetic level indicator (MLI) is used for an easy, non-electronic visual representation of the level measurement. In the other, the company had been using a guided wave radar. The guided wave radar worked, but maintenance employees had no way of safely servicing or cleaning the sensor without stopping the process.

Operators wanted a level measurement sensor that could be isolated from the corrosive materials it was measuring. To do this, however, the new technology would have to be non-contact and have the ability to make accurate, reliable measurements in the tightly enclosed space of the bridle. Already familiar with the 80 GHz VEGAPULS 64, the company enquired about testing the sensor and pushing its limits in such an enclosed space.

During the installation, technicians installed a double block and bleed valve to isolate the process from the sensor when necessary. The VEGAPULS 64 began receiving a strong return signal immediately. The new non-contact radar sensor provided an accurate measurement despite the uphill battle.

When an isolated, non-contact measurement is paramount At both chemical facilities, isolating level measurement instrumentation was critical to their process.

On large storage vessels, a double block and bleed process connection with the 80 GHz VEGAPULS 64 mounted on top is an excellent solution. With the radar sensor mounted this way, operators can remove the instrumentation, perform maintenance, or swap it out entirely without ever emptying the vessel. Operators only receive a small interruption in level measurements while the sensor is offline, and there is no need for a process shutdown.

At the same time, high-value processes can mount the 80 GHz VEGAPULS 64 to a flushing ring and knife gate valve to minimise downtime for cleaning and maintenance. Creatively mounting the sensor like this keeps the process running longer with fewer shutdowns, and operators continue to receive a consistent level measurement.

When it comes to corrosive substances, the high focus of 80 GHz radar allowed the East Coast facility to use radar technology on an existing bridle. The facility was also able to add a block and bleed system to improve employee safety without sacrificing measurement reliability or accuracy.

For many applications, isolating instrumentation is a necessity for safety or monetary reasons. Regardless of the purpose, an 80 GHz radar mounted on a ball valve, knife gate valve, or a more complex block and bleed valve provides a safe and cost-effective solution that operators can depend on.

Ryan Gane, ROSEN, USA, examines how technology that can collect high-resolution data of tank bottoms can help enable long-term integrity management plans.

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henever someone gets a new job, they have a decision to make on how best to tackle it. Is it best to carry out the job exactly as it was done before, or to introduce a new way of doing things? A new way may not necessarily be better, but as things change and new procedures and technology are introduced to the market, there are perhaps ways to upgrade the approach to the job. This was the case for IES Downstream LLC (IES) when it added assets to its portfolio. For companies with assets as valuable as storage tanks in a terminal, ensuring their integrity over the long-term is vital to safe and profitable operation. As such, collecting as much information as possible is essential.

IES, which owns and operates storage tank assets in the Hawaiian islands, was looking for robust and thorough tank inspection data. It wanted to increase the detail and accuracy of its storage tank data so that it could make better risk-based inspection (RBI) decisions regarding operational intervals. The first two tanks to be assessed with this initiative were located at its Kapolei and Honolulu terminals on the island of Oahu.

Putting data to good use IES wanted the most accurate and highest-definition inspection data possible on its tank bottoms to ensure all areas of corrosion were properly identified, sized, mapped and assessed.

This goal went beyond understanding the current integrity state of the assets. The data would be used to create a long-term integrity management plan, facilitating decisions on potential future inspection intervals (i.e. in the next 5, 10, 20 or even 30 years). Due to the fact that the storage tank floors were relatively new, this would require a significantly low threshold on the tank bottom to achieve more than a 20 year inspection interval. In addition, IES wanted to be sure to get the most out of the collected data and use it to conduct a risk-assessment in order to determine what repair intervals were needed on the tank floor, where qualitative data is crucial. The company approached the ROSEN Group for help.

High-quality collection Considering the operator's need for high-quality data, the ROSEN Group recommended the Tank Bottom Inspection Tool 3 37 Summer 2021

(TBIT Ultra), which has the ability to measure metal loss or defects with a thickness as small as 10% of the plate material.

This is a considerable improvement from the 20% thickness change at which most tools are able to perform. Through the unique placement on the measurement unit itself, the TBIT Ultra has 1029 magnetic flux leakage (MFL) sensors, which is considerably more than the 154 of the standard TBIT. This allows for a resolution that is 6.7 times higher, meaning that the detection of pitting and pinhole defects down to 2 mm dia. is possible. Sizing accuracy in terms of depth of any metal loss defects has increased from +/- 0.2 t to +/- 0.04 t. Moreover, the ability to detect defects through tank bottom coating has improved. With the TBIT Ultra, coating thickness up to 6 mm (0.236 in.) still allows for automatic sizing, and defects can still be detected with a 6 – 10 mm (0.236 – 0.393 in.) coating thickness.

The new tank bottom inspection tool uses signal-based sizing rather than the amplitude measurement techniques usually used. Amplitude-based MFL tank bottom inspection tools act as screening tools; they identify where to find defects based on a predefined amplitude threshold, but they

are not able to identify smaller but deeper defects, as these do not usually breach the threshold. Once tank bottoms are inspected with these tools, additional inspections using other technologies, such as ultrasound, generally need to follow in order to obtain accurate sizing. In comparison, signal-based sizing means all features are recorded, mitigating any risk of missing small but deep features. Features are also sized based on their signal pattern in length, width and depth, so any risk of sizing inaccuracy due to defect morphology is mitigated.

MFL amplitude is strongly dependent on the length and width of a feature; therefore, an uncritical pit with a large diameter will produce a higher MFL amplitude than a critical but small pit. The predefined threshold means the feature may be overlooked entirely. Essentially, using an amplitude-based MFL tool is like taking a metal detector to the beach: it will identify where to find something, but you will have to be the one to dig it up to find out the details. The TBIT Ultra has automated feature sizing, which means the inspection turnaround time is faster, and the asset can be put into operation almost immediately after the data is collected. The automated component also results in a decrease in human error. Of course, the competence of inspectors and technicians is vital to the success of any inspection.

However, to achieve consistent results when performing a repetitive task in harsh environments (which is definitely the case when manually inspecting the inside of a tank), automation is a necessity.

In terms of inspection operation, IES requested that all the data collection take place during the out-of-service period, before determining the best path forward in terms of interval and repair strategy.

Once the inspection had been completed, this was easily achievable with software dedicated to tank integrity management. In order to better visualise the data, the software allows analysts and operators to adjust the metal-loss-marking threshold, shown as a percentage, clearly indicating the condition of the bottom and any overall corrosion. It is also possible to view features on both the product side and the soil side to better understand the damage mechanisms occurring within the storage tank.

Figure 1. IES employed the TBIT Ultra to provide high-resolution data, allowing for increased confidence in integrity management decisions.

Figure 2. Signal-based MFL allows for the detection of all

features, ensuring nothing is missed when making repair or future management decisions.

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Pro-active integrity management Once the storage tanks had been cleaned for inspection, the assessments of their condition were completed quickly. The data collected, along with the bottom repair strategy and the software, were given to the operator while still on-site. This allowed them to make rapid decisions based on the available data.

The final reports were completed within 96 hours of the inspection, which included the API 653 inspection as well as relevant drawings and checklists. Using this high-resolution data set, IES is now able to manage these storage tanks more effectively; inspection intervals can be planned, and risk-based assessments can be conducted, empowering operators to be more pro-active in their integrity management while ensuring a safe, compliant, and extended lifetime for all assets.

A

Ian Wade, Belzona Polymerics, UK, outlines the benefits of protecting storage tanks with sprayable, polymeric coatings.

slow-down in bulk liquid usage is putting increasing pressure on tank farm assets to either maintain, replace, or expand their current storage tank capacity.

In these unprecedented times, maintenance and inspection of tank integrity may be overlooked or ignored. This is especially true for newer tanks, as these should be constructed with the addition of a corrosion protection lining. However, this is not always the case due to costs or the expectance that any corrosion allowance will be minimal.

There is an added pressure on the turnaround times of any planned scheduled maintenance or inspection intervals. These also may be delayed, resulting in reactive measures (such as weld repairs or the introduction of a lining) which can cause irreversible deterioration of the substate with through-wall defects and loss of containment, ultimately landing the asset owners with hefty costs and fines.

If planned maintenance does go ahead, it is important to identify the following key areas to sustain the fit-for-purpose use of storage tanks.

39 Summer 2021 3

Pitted areas If the internals of the tank steel are exposed, or a less sufficient coating is used, then pitting corrosion can occur.

Exposed steel is more susceptible to corrosion and chemical damage. The pits can become either wide and shallow or narrow and deep, which can quickly affect the wall thickness of the steel, becoming penetrated and requiring immediate action. Pitted areas can be repaired by weld overlay or welding a plate over the top, but these may have inherent issues such as heat affected zones (HAZ). The intense process of heating and subsequent cooling of the substrate can generate weaknesses in the metal and limit the structural integrity at the weld point.

Cold applied epoxy repair composites can be utilised to repair deep pits quickly, restoring large areas to their original profile and avoiding the need for hot work.

Weld and seams The causes of failure of welded structures are often associated with low quality joints. The defects arise from deviations from the principles of welding technology, the use of inadequate primary techniques, additional welding material, or poorly qualified welders.

There are several common weld deposit/base metal combinations that are known to form galvanic couples.

Even when special care is taken to select the materials, certain environments can worsen the issue.

To eliminate the need for any welding repairs, epoxy-based paste grades in conjunction with reinforcement sheets can isolate the weld seams and protect them from any further corrosion.

Conventional linings Conventional linings can provide limited chemical resistance at high temperatures. However, they also contain solvents which can complicate applications from a health and safety point of view, with specialist environmental controls required – especially in the confined spaces of a tank.

If a lining system, such as glass flake, is damaged or fails in service, it is very difficult to perform isolated repairs. Generally, the full system would require removing before applying a new system.

The root causes of coating defects such as delamination, blisters, cissing and cracking need to be identified in order to avoid triggering further problems in the connecting pipelines or filtration systems.

Cleaning regimes Cleaning regimes are an often-overlooked factor when renewing or rejuvenating current assets. Ultra-high pressure washing at elevated temperatures and the potential use of strong chlorinated chemicals can cause penetration into the coating, resulting in swelling, softening and even dissolving of the coating. In this case, before any inspections of the coating take place, it would be visually evident that the tank will require full replacement.

To spray or not to spray?

Figure 1. A high voltage spark tester.

Table 1. Suggested voltages for high voltage spark testing Total dry film thickness

Suggested inspection

μm

mils

Voltage

200 – 280

8 – 11

1500

300 – 380

12 – 15

2000

400 – 500

16 – 20

2500

530 – 1000

21 – 40

3000

1010 – 1390

41 – 55

4000

1420 – 2000

56 – 80

6000

2060 – 3180

81 – 125

10 000

3200 – 4700

126 – 185

15 000

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Full lining of the tank may be ideal, but it is not always an option. In some instances, heated oil storage tanks can contain traces of water which corrode the bottom of the tank. At elevated temperatures, this can increase the rate of corrosion expected. As a minimum, internal linings can be applied 1.5 m from the bottom of the tank up, as there tends to be higher levels of corrosion in this area. This is also useful for when maintenance budgets are tight, and may also save costs for the asset owner without the need for scaffolding or platforms to be erected and dismantled while applying any coating system.

If a tank is storing liquids or gases, or creates a vapour phase due to heating, then a full lining of the tank, including the roof, is the only option.

When selecting a corrosion protection lining for storage tanks, a few keys requirements should be considered: Quick and easy application.

Corrosion protection.

Chemical resistance.

High temperature resistance.

Inspectable and easy maintenance.

Conventional sprayable ceramic-filled coatings not only cause extensive damage to spray equipment, but

also provide a limited level of erosion corrosion protection. However, improvements in sprayable epoxy technology mean that they can be sprayed more quickly, offer more flexibility, and create a higher film build-up and higher temperature resistance if required.

Sprayable epoxy systems have been proven to reduce downtime and enhance return to service, whilst also offering 24-hour overcoating windows, reducing the pressure inflicted on applicators to apply a two-coat system. Solvent-free materials also allow it to be safely applied in confined areas, with chemical resistance against a wide range of chemicals including hydrocarbons and amines.

With the use of standard airless spray equipment, epoxy linings can be applied effortlessly, but only if the correct set-up has been achieved. For instance, the water temperature for the heat trace lines that introduce heat into the coating as it travels from the pump to the spray gun, thus lowering its viscosity, need to attain a spray tip temperature between 40 – 45°C. The correct inlet pressure for pumps with ratios from 56:1 up to 80:1 and the correct spray tip are all crucial for any spray application to run successfully.

The expected wastage factor involved with spray applied coatings using single leg airless spray equipment can be in the region of 30 – 40% due to the lining being pre-mixed before entering the pump. This is lower for plural systems, as unmixed material is pumped to a mix manifold before making its way through a minimum 15 m whip line. This includes two inline fluid mixers to further mix the components before reaching the spray gun, meaning that any wastage is within the 15 m of lines with the added benefit of being able to recirculate the unmixed material back into the relevant tins.

In comparison, a hand applied wastage factor can be 10 – 20%; however, the possible coverage achievable is less. This can be up to 10 times quicker with spray applications than hand.

The skill of the sprayer will also determine the uniformity of the applied coatings. If applied too thin, the coating may not perform for as long as expected. If applied too thick, it can eat away into potential savings and could cause issues in service.

On the completion of any linings, it is important to visually inspect the coatings for any misses or debris when the lining has achieved its minimum cure or hardness. Further inspection can then proceed.

Most coating inspections used to confirm continuity are carried out with a high voltage spark tester/holiday detector (Figure 1) in accordance with international standards (such as NACE SP 0188) which, following the manufactures guidance, can be set at the expected minimum thickness of the coating (Table 1). Once the probe passes over a flaw or pinhole, completing the circuit to the earth return, an alarm will be set off. The coating inspector or maintenance team will mark these areas for remedial work which, if the lining’s overcoat window allows, can be easily applied over the marked-up area without any surface preparation. All these steps can ensure full longevity of the lining.

Figure 2. A Belzona polymetric coating being spray applied.

Return to service The importance of return to service is crucial for asset owners. Once the lining has achieved a certain level of cure, the asset can be placed back into service. In some cases, assets can be back to service within less than 24 hours of the final application due to the chemical nature of epoxy systems.

When mixed, epoxy systems cure through chemical exothermic reactions. This is generally done at ambient temperatures, but there may be circumstances where a quick return to service is desired. The client can post/force cure the epoxy linings in service if the required level of temperature can be reached. This allows any free polymers to find other free polymers, achieving better cross linking and ultimately improving the chemical or temperature resistance of the applied lining.

When a lining is subjected to service conditions, this can affect a coating’s lifespan. Sprayable epoxy systems are easy to inspect at any time during their expected life expectancy using dry film thickness (DFT) gauges, high voltage spark testers, ultra-sonic (UT) gauges or Xray machines, making any scheduled maintenance checks seamless.

If the thickness of the lining has been reduced by erosion, general defects from mechanical damage, or is simply coming to the end of its service life expectancy, straightforward remedial work can be performed on the coating, potentially without the need for a full replacement of the lining.

In conclusion, sprayable 100% solid epoxy systems can be utilised to speed up application time with the use of standard spray equipment while simultaneously reducing overall costs. The maintenance and easy inspection of the lining is paramount to ensuring a long useable life of the lining.

41 Summer 2021

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any storage terminals and petrochemical facilities are located near a navigable waterway and have shore marine structures nearby to allow for tanker traffic to receive or send product. These could include docks, jetties, piers, seawalls, mooring, and turning/mooring dolphins and other similar structures. These metallic structures are subject to corrosion and are generally protected by cathodic protection systems. This article provides a general overview of cathodic protection for these structures and discusses some of the common strategies that are frequently employed to protect them.

Two basic types of cathodic protection There are two basic types of cathodic protection and both are used to protect near shore marine structures. It is not uncommon to employ both strategies to protect different structures in the same facility. Each of these systems have their advantages and disadvantages, and it is important that the design engineer consider the application specifics to choose the appropriate system(s) for the application.

The first type of system is a galvanic anode system (also commonly referred to as a sacrificial anode system). Galvanic anodes are cast hunks of a specific metal alloy that are typically attached directly to the structure. For seawater applications, these are commonly aluminium or zinc anodes, while brackish or freshwater applications might utilise zinc or magnesium anodes.

These metals are inherently more electro-negative than steel so that when they are coupled to a steel structure, current will flow from the more electro-negative anode to the metallic structure.

When properly applied, this electrical current, generated from the anode, flowing through the electrolyte (water) to the structure (or cathode), reduces the corrosion rate to virtually nothing – this is, by definition, cathodic protection.

The other type of system is an impressed current system.

Impressed current systems work in the same basic manner as Summer 2021 42

galvanic systems; however, for these systems, an external power supply is used to drive current off the anode, through the electrolyte, to the structure being protected. The use of an external power supply allows the cathodic protection system to utilise anodes that are not required to be more electro-negative than the structure being protected. These anodes can be chosen for other properties, namely their ability to discharge current much more cost-effectively than massive hunks of metal alloy.

They can do this because of the use of an external power supply that will drive the flow of current.

Key differences between galvanic and impressed current The key differences between an impressed current anode system and a galvanic anode system for near shore marine structures are discussed here:

Anode consumption rates Aluminium alloy anodes, such as those typically used in seawater applications, have a nominal capacity of 2000 amp-hr/kg, while titanium anodes with a mixed metal oxide coating (MMO), commonly used in near shore applications, have a capacity of approximately 1000 times the equivalent capacity of aluminium anodes. This means that far fewer anodes are required and the expected life of the system can be much longer.

Current density limits Aluminium alloy anodes can operate at a maximum current density (current being discharged for a given surface area) of 15 amps/m2 but are typically designed to operate at much lower current densities. Impressed current MMO type anodes can operate at current densities up to 500 amps/m2; however, in most cases the operating levels are much lower. The higher current density limit means that the designer can use fewer impressed current anodes at a much higher output.

Ted Huck, MATCOR Inc., USA, explores cathodic protection options for terminal marine structures including docks, jetties, piers, seawalls and pilings.

Driving voltage Aluminium alloy anodes have a natural potential difference of approximately 0.5 V between the anode and the steel structure being protected. This is the limit of the driving force available to the cathodic protection (CP) designer when using galvanic anodes. Impressed current anodes utilise an external power supply typically operating at 10 – 30 V of driving force, which allows fewer anode systems to protect larger structures with high current requirements.

No power supply While aluminium alloy anodes are not as efficient or as powerful as impressed current anodes, in many applications the ability to operate without the use of an external power supply is a huge advantage. The need for electrical power and extensive electrical cabling is greatly diminished or eliminated with galvanic systems.

Ultimately, the system designer needs to be familiar with both options and make an economic evaluation of the appropriate approach taking into consideration anode system life, material and installation costs, operating factors and constraints, and other factors to determine which type of system is best for a given application.

Land side design considerations While this article is focused on near shore marine structures, it is important to note that these structures almost always consist of a mix of wetted surfaces and buried surfaces.

Consider a sheet pile wall being installed as part of a new berthing facility. One part of the structure is exposed to the water, while the other side of the same structure is exposed to soil. Both sides of the sheet wall are subject to corrosion and must be considered by the corrosion engineer. Typically, soil has a much higher resistance than seawater, brackish water, or even fresh water. Because of the higher soil resistance, land

side protection is more often accomplished using impressed current systems because of the large amounts of current required to protect them.

Another important consideration for land side cathodic protection has to do with other nearby structures, including grounding systems, buried pipelines, storage tanks both above and below ground type, and/or building foundations. These ‘foreign’ structures can all have an impact on the performance of the cathodic protection system and must be considered during the design and installation.

Water side considerations When designing anode systems to protect the wetted surfaces of these structures, there are some important considerations that must be given during the design. The first consideration is installation: can the anodes be installed prior to the structure being installed? Water side installations can get very expensive if specialised industrial marine divers and diving support equipment and personnel are required. In some cases, the anodes can be cost-effectively installed on the structure prior to the structure being erected. In other cases, the installation of brackets and other devices can be designed and installed in advance, thereby minimising the installation efforts required for a successful anode installation.

Another important consideration for water side installations is the anode location. For galvanic anodes, the anodes are often located in very close proximity to the structure, but for impressed current anodes, the anodes are generally located some distance away from the structure to allow the higher capacity anodes to cover a larger area of the structure. This might mean putting an anode on the sea floor well away from the structure. For these sea floor type anodes, issues such as dredging become critical. Installing a remote anode in a location where dredging may occur would likely 4 43 Summer 2021

be a concern. In some cases, steep concrete sloped channels might preclude the use of anodes positioned on the sea floor as they may not remain in place.

Another concern that applies to extreme cold-water applications is freezing. In these applications, ice floes can cause severe damage to anodes and cabling systems alike.

New construction vs retrofit application Another factor that the designer must consider is whether this is a new installation or a retrofit application. For new installations, site access issues may be quite different than for an existing structure requiring a cathodic protection system replacement. For new installations, the option to have anodes or anode fixtures installed on structures prior to their installation can have a tremendous impact on the overall installation costs – something that may not be an option when addressing an existing structure.

Case study Along the Houston Ship Channel, Texas, US, there is a large concentration of terminals and petrochemical facilities, and almost all of them have some form of marine loading/unloading facility. On a recently completed project,

Figure 1. Vertical drill rig used to install deep anode

systems in a vertically drilled hole, typically to depths of 50 – 150+ m.

Figure 2. Sled Anode Assembly being installed in the channel using a barge mounted crane to protect the combi-wall in the foreground.

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a terminal facility had an old sheet pile wall that was approaching the end of its useful life and was scheduled for a replacement system to be installed in the same location.

The project consisted of installing cathodic protection for a new 275 ft-long combi-wall that was being installed directly in front of an existing sheet pile wall. The new combi-wall utilised 60 in. dia. steel pipe pilings connected with conventional Z pilings driven to a depth of 100 ft. In addition to the new wall, new dolphins were being installed in the channel for mooring and turning purposes.

The system designer had multiple structures to consider and elected to use a range of cathodic protection solutions.

For the isolated dolphins located in the channel, conventional galvanic anodes were installed with the dolphins. These small, isolated structures were ideal for direct connected zinc galvanic anodes and eliminated any requirements for extensive cabling in the channel. Given the brackish nature of the Houston Ship Channel, zinc anodes were the preferred anode system for this application.

The water side of the new combi-wall was designed to be protected using two sled-type anodes located in the channel with cabling routed back to shore. Sled anodes are typically used to protect large surface areas utilising relatively high output anodes – commonly titanium coated MMO type anodes, given their long life and high efficiency.

The sled anodes are built with concrete ends to secure the sled in place on the channel floor. The sleds manufactured for this application were a little over 5000 lbs each. One of the advantages of a sled anode is the ease of installation.

The anodes are lowered in place using a crane, and the cabling is routed back to shore with weights to hold the cabling in place. The entire installation takes only a few hours per anode assembly.

The space between the existing sheet pile wall and the new combi-wall was filled with soil, and individual titanium-coated MMO tubular anodes were installed every 10 ft to protect both the interior surface of the new wall and the exterior surface of the existing wall. MMO tubular anodes are available in a range of sizes, and for this application the tubes selected were standard 1 in. dia. x 1 m long tubes. In addition to installing the tube anodes, soil access tubes were provided to assure future access for testing.

The interior surface of the existing wall had previously been protected by a deep anode installation, and the project included replacing in kind that system which was nearing the end of its useful life. Deep anode systems are commonly used in facilities where surface real estate is at a premium. A vertical hole, typically 8 – 10 in. dia., is drilled to a depth sufficient to have the anodes be considered remote from the target structure – usually 200 – 300 ft in depth.

Anodes are installed in the bottom of the hole and the hole is filled with a conductive carbon backfill to improve the anode performance. The top of the hole is filled with gravel, sand or bentonite to complete the installation.

For this example, project to protect this new sheet pile wall, a combination of anode types, installation methodologies, and anode configurations were employed to provide what the designer hoped would be an optimal installation.

Richard Vann, RVA Group, UK, explores the process and benefits of asset retirement planning, and why operators should start thinking about the end of a tank’s life earlier than expected.

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eing prepared for the retirement of an asset is a fundamentally crucial and strategic way to approach the operational lifecycle of a tank farm, or even an entire terminal. In many parts of the world, it is also a legal requirement – to comply with international financial provisioning standards such as FAS143 in the US, and IAS 37 in Europe.

The roots of such standards date back to the days of events such as the ‘Enron scandal’, when the American energy giant was declared bankrupt. The company was building and running power facilities throughout the US and overseas – seemingly successfully. However, despite sizable annual revenues, no financial provisions were being made to fund the eventual decommissioning of Enron assets when the time came to take them offline. The liquidation of this company – and the fact that the government had to pay for the retirement of their plants – certainly acted as a lesson learnt, and accounting rules were changed as a result.

Now, a proportionate amount of money must be set aside every year for the decommissioning of high value capital assets with an expected life in excess of 15 years. If nothing else, this acts as a safety net in the event of abandonment.

Comprehensive financial provisioning While the numbers associated with asset retirement were once estimated, they must now be evidenced and substantiated.

In other words, accounting law now states that asset retirement provisioning should be carried out in a proven manner, which naturally requires someone with decommissioning-specific expertise to be involved in the exercise.

Nobody knows an asset better than the operator who runs it, but that does not mean that the operator knows exactly how to retire the asset with maximum respect for safety, the environment and their bottom line. The many 4 45 Summer 2021

components of a decommissioning project – including decontamination, dismantling and demolition – require a defined engineering skill-set, if the assignment is to be managed and executed successfully.

The ‘numbers’ must therefore include estimates of the resources that will be required – in terms of people and technology – over a given period of time, as well as considered third party cost estimates relating to everything from the surrender of licences and permits, through to community engagement, wider stakeholder liaison and the disposal of hazardous materials, to name just a few.

The data is then typically compiled in a transparent report with annotations to explain any assumptions and exclusions. Once audited, the figures are declared in operators’ annual results.

More than financial data Of course, such accounting requirements do not exist in all parts of the world, but parentage of an asset naturally dictates the standards adopted, irrespective of where the

Figure 1. Tank farm and terminal decommissioning requires a defined engineering skill-set.

Figure 2. The decommissioning of tanks, terminals

and other buildings and structures is increasingly being considered before they have even been built.

Summer 2021 46

asset actually resides. Consequently, this process forms part of common practice for a significant proportion of the industry and the data is produced without question, much like a tax return. In larger firms, the numbers also tend to aid compliance with organisations’ own financial regimes.

But delve deeper, beyond the headline summaries, and what do the figures actually say? This asset retirement exercise is one of many strategic studies that an operator can undertake to highlight, understand and better manage a site’s long-term liability. In fact, if used properly alongside a redundant asset management plan (RAMP), the operator has an extremely powerful resource at their fingertips.

For example, RVA began working with one European firm back in 2011 because, with >€100 million of redundant assets, it had reached the point where it was almost unaware of what it had got. Therefore, the firm sought a true and complete picture of its decommissioning responsibilities – a value-adding business instrument – not just an indicative cost.

It is also important to note that the aforementioned accounting standards require operators to evaluate all of their assets. However, in truth, fuel storage/distribution facilities and terminals may sometimes be considered with less rigour on certain sites, in favour of concentrating on elements of a plant that are considered more complex or hazardous in nature. This should not be the case.

Thorough analysis of all the client’s assets means that a decommissioning ‘hierarchy’ can be drawn up according to the level of safety risk associated with each. The deterioration of insulation or the general corrosion of a tank heightens the likelihood of a containment loss, for instance. Structural collapse is also a significant risk, as well as leakage, which may consequently affect the need to accelerate the retirement of the asset concerned.

Monitor, measure and adapt Once complete, the frequency with which an asset retirement study should be reviewed must be judged on a case-by-case basis. It is recommended that the information is rigorously re-assessed at least every five years. This allows any changes to the assets or tightening of regulations to be accommodated, and the true liability of a site to be fully understood at a given point in time.

A solid baseline of data will ensure this ongoing review process can be carried out in both an efficient and effective manner. At the heart of the costings exercise should therefore be a fluid and reconfigurable database which allows for the adjustment of resource costs, waste and scrap rates, as well as annual inflation figures. This adaptability is essential if the study is to maintain relevance over a possibly extended period.

In truth, the frequency with which an operator chooses to update their asset retirement data often depends on their individual approach to good governance. For example, a tank explosion in Western Asia in 2016 had devastating consequences that a different care and maintenance regime could perhaps have helped to prevent.

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With the current tendency for assets to change ownership perhaps more often than in the past, variations of this asset retirement study can also be used by prospective purchasers and vendors as a due diligence tool. For example, the information gathered gives clarity on the legacies that will remain with the site and costs that are likely to crystallise in the future.

Thinking about decommissioning before day one

Figure 3. Analysis of site assets means a decommissioning hierarchy can be drawn up according to risk levels.

The wider value of asset retirement data As has been evidenced, this accounting practice can add value far beyond that of a compliance box-ticking exercise. As the age-old saying goes, knowledge is power, so hopefully it is viewed as much more than merely a ‘necessary evil’.

Therefore, if an operator is devising a business case for the installation of a new plant, considering a site exit, or evaluating the affordability of a decommissioning project over a defined period of time for cash-flow purposes, strong intelligence already exists.

The role of asset retirement provisioning is only going to grow – as is the importance of decommissioning in the oil and gas value chain.

This is because the circular economy has gone from being a term usually referenced only by those in the environmental sector, to a philosophy now influencing many supply chains in various industrial settings.

When it comes to the futureproofing of assets in this sector and in many areas of construction, the decommissioning of tanks, terminals and other buildings and structures is therefore increasingly being considered before they have been built – even while they are still being designed.

Reuse and recycling matters more than ever, so if the financially and environmentally savvy retirement of an asset can be ensured before it even exists, this takes an operator’s corporate social responsibility (CSR) status to a whole different level – and rightly so. Conversation surrounding this topic is only likely to grow.

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